Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer. Thus, the porous layer forms a reservoir, that is, a volume in which hydrocarbons accumulate. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
A modern oil well typically includes a number of tubes extending wholly or partially within other tubes. That is, a well is first drilled to a certain depth. Larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. After the initial section has been drilled, cased, and cemented, drilling will proceed with a somewhat smaller well bore. The smaller bore is lined with somewhat smaller pipes or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A well may include a series of smaller liners, and may extend for many thousands of feet, commonly up to and over 25,000 feet.
Hydrocarbons, however, are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
Perhaps the most important stimulation technique is the combination of horizontal well bores and hydraulic fracturing. A well will be drilled vertically until it approaches a formation. It then will be diverted, and drilled in a more or less horizontal direction, so that the borehole extends along the formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Fractures then are created in the formation which will allow hydrocarbons to flow more easily from the formation.
Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the fluid along with gelling agents to create a slurry. The slurry is forced into the formation at rates faster than can be accepted by the existing pores, fractures, faults, vugs, caverns, or other spaces within the formation. Pressure builds rapidly to the point where the formation fails and begins to fracture. Continued pumping of fluid into the formation will tend to cause the initial fractures to widen and extend further away from the well bore, creating flow paths to the well. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation rarely will be fractured all at once. It typically will be fractured in many different locations or zones and in many different stages. Fluids will be pumped into the well to fracture the formation in a first zone. After the initial zone is fractured, pumping is stopped, and a plug is installed in the liner at a point above the fractured zone. Pumping is resumed, and fluids are pumped into the well to fracture the formation in a second zone located above the plug. That process is repeated for zones further up the formation until the formation has been completely fractured.
Once the well is fractured, large quantities of water and sand that were injected into the formation eventually must be allowed to flow out of the well. The water and sand will be separated from hydrocarbons produced by the well to protect downstream equipment from damage and corrosion. The production stream also may require additional processing to neutralize corrosive agents in the stream.
Systems for successfully performing a fracturing operation, therefore, are extensive and complex, as may be appreciated from FIG. 1. FIG. 1 illustrates schematically a common, conventional frac system. Water from tanks 1 and gelling agents dispensed by a chemical unit 2 are mixed in a hydration unit 3. The discharge from hydration unit 3, along with sand carried on conveyors 4 from sand tanks 5 is fed into a blending unit 6. Blender 6 mixes the gelled water and sand into a slurry. The slurry is discharged through low-pressure hoses 7 which convey it into two or more low-pressure lines 8 in a frac manifold 9. The low-pressure lines 8 in frac manifold 9 feed the slurry to an array of pumps 10, perhaps as many as a dozen or more, through low-pressure “suction” hoses 11.
Pumps 10 take the slurry and discharge it at high pressure through individual high-pressure “discharge” lines 12 into two or more high-pressure lines or “missiles” 13 on frac manifold 9. Missiles 13 flow together, i.e., they are manifolded on frac manifold 9. Several high-pressure flow lines 14 run from the manifolded missiles 13 to a “goat head” 15. Goat head 15 delivers the slurry into a “zipper” manifold 16 (also referred to by some as a “frac manifold”). Zipper manifold 16 allows the slurry to be selectively diverted to, for example, one of two well heads 17. Once fracturing is complete, flow back from the fracturing operation discharges into a flowback manifold 18 which leads into flowback tanks 19.
Frac systems are viewed as having “low-pressure” and “high-pressure” sides or, more simply, as having low sides and high sides. The low side includes the components upstream of the inlet of pumps 10, e.g., water tanks 1, hydration unit 3, blending unit 6, and the low-pressure lines 8 of frac manifold 9, which operate under relatively low pressures. The high side includes all the components downstream of the discharge outlets of pumps 10, e.g., the high-pressure missiles 13 of frac manifold 9 and flow lines 14 running to goat head 15, which operate under relatively high pressures.
The flow lines and units making up the high-side of a frac system, such as pump discharge lines 12 and flow line 14, typically are assembled from a large number of individual components often referred to as “frac iron,” “flow iron,” or “ground iron.” Such components include straight steel pipe, fittings for splitting, combining, or changing direction of a line, gauges and other monitoring equipment, and valves and other control devices. Flow iron components are fabricated from heavy, high tensile steel and are quite rugged. They may be rated for high-pressure service up to 20,000 psi.
Because frac systems are required at a site for a relatively short period of time, frac iron components often are joined by unions. Unions allow the components to be connected (“made up”) and disconnected (“broken down”) relatively quickly. The three types of unions commonly used in frac systems are hammer (or “Weco®”) unions, clamp (or “Greyloc®”) unions, and flange unions. Though spoken of in terms that may imply they are discreet components, unions are actually interconnected subassemblies of the components joined by the union. A male sub will be on one component, and a mating female sub will be on the other. The subs then will be connected to each other to provide the union.
The optimal volume, pumping rate, and pumping schedule for a fracturing operation will be determined in view of the physical properties of the formation, the depth at which it will be fractured, and the fluid that will be pumped into the formation. Such pumping regimens may vary considerably and, as noted above, typically proceeds in multiple stages. Thus, fluid flow through the frac system is carefully controlled and monitored throughout the operation.
Fluid is designed to flow through most of a frac system in only one direction: towards the well. Once pumping is stopped, however, large quantities of slurry will flow out of the well at rates and pressures at least initially comparable to those used to fracture the well. Shut off valves will be installed in the system to divert that return flow into recovery tanks and to protect upstream portions of the system. In particular, pumps must be protected against back flow. Actuating shut off valves, however, may take some time. Operators also may neglect to open or shut the appropriate valves. Thus, frac systems commonly will incorporate various automatic check valves to ensure that fluid is able to travel in only one direction through a particular part of the system.
The check valves in frac systems generally are “flapper” style check valves. Flapper valves, as their name suggests, incorporate a pivoting flapper. The flapper normally hangs down, under the influence of gravity, across the face of a seat provided in the valve conduit. Fluid flowing through the valve conduit in the desired direction will push against the flapper, causing it to swing up and allow fluids to pass through the valve. Flow in the opposite, undesired direction, however, will cause the flapper to bear and seal against the seat, shutting off back flow through the valve.
Flapper valves are better suited than other check valves, such as dart check valves, for systems handling particulate laden, abrasive fluids such as frac fluids. Particulate matter is less likely to interfere with the operation of flapper valves. Eventually, however, the flapper and seat can become eroded such that the ability of the valve to check flow in the opposite direction is impaired. Thus, many conventional flapper valves have designs which allow the flapper and the seat to be replaced periodically. Such valves include what may be referred to as inlet entry and top entry designs.
Inlet entry designs, such as Weco® flapper check valves available from FMC Technologies, Inc, Houston, Tex., have a replaceable assembly that includes both the seat and the flapper. The seat-flapper assembly is carried within the valve conduit. The assembly may be accessed for replacement by disassembling a two-part valve body. Once the inlet end of the valve body is removed, the seat-flapper assembly may be pulled out of the outlet end, and a new assembly inserted. Necessarily, however, the valve must be disassembled from the flow line in order to replace either the flapper or the seat.
Top entry designs have separate flappers and seats which may be accessed through a service port. Examples of such top entry flapper valves include those available from Tech-Seal International (TSI Flow Products), Houston, Tex., Weco top entry valves available from FMC Technologies, and SPM® 1502 clapper valves available from S.P.M. Flow Control, Inc., Fort Worth, Tex. In top entry valves, the valve body is a single integral piece which is provided with a service port extending from the top of the valve into the valve conduit. The service port is covered by a cap which can be removed to access the flapper and seat. The seat, for example, may be carried in the inlet end of the valve conduit. The flapper may be mounted on a bracket which rests on a shoulder in the service port and is held there by the access cap.
A primary advantage of top entry valves is that the flapper and seat may be replaced without removing the valve from a flow line. A disadvantage lies in the installation of the seat. The seat must be installed securely so that it is not displaced as fluid flows through the valve. Threaded seats are difficult to align with the flapper, and so typically threaded seats are provided with vertical seat faces. Pressure fitted seats may be difficult to install and remove. With both approaches, special tools may be required.
Flapper valves, like other flow iron components, are fabricated from steel and are quite rugged. Nevertheless, they can suffer shortened service life or failure due to the harsh conditions to which they are exposed. Not only are fluids pumped through the system at very high pressure and flow rates, but the fluid is abrasive and corrosive. Components may suffer relatively rapid erosion. Any failure of flapper valves on site may interrupt fracturing, potentially reducing its effectiveness and inevitably increasing the amount of time required to complete the operation.
Frac jobs also have become more extensive, both in terms of the pressures required to fracture a formation and the time required to complete all stages of an operation. Prior to horizontal drilling, a typical vertical well might require fracturing in only one, two or three zones at pressures usually well below 10,000 psi. Fracturing a horizontal well, however, may require fracturing in 20 or more zones. Horizontal wells in shale formations such as the Eagle Ford shale in South Texas typically require fracturing pressures of at least 9,000 psi and 6 to 8 hours or more of pumping. Horizontal wells in the Haynesville shale in northeast Texas and northwest Louisiana require pressures around 13,500 psi. Pumping may continue near continuously—at flow rates of 2 to 3 thousand gallons per minute (gpm)—for several days before fracturing is complete.
A problem with all flapper valves derives from the fact that they necessarily require an enlarged area within the passage to accommodate installation and operation of the seat and flapper. That is especially true for inlet entry designs. The enlarged portion of the passage in turn cause turbulence in fluids flowing through the valve. Turbulence in the valve not only creates pressure losses in the flowline, but can dramatically increase the rate of erosion in the valve, especially when the fluids are laden with abrasive particulates. The seat and flapper in particular are highly exposed to turbulence in the valve and its attendant erosion.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved pressure release valves and methods for protecting high-pressure flowlines from excessive pressure. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.